COMPETITIVE ELECTRICITY MARKET DESIGN:A WHOLESALE PRIMER

WILLIAM W. HOGAN

December 17, 1998

Center for Business and GovernmentJohn F. Kennedy School of Government

Harvard UniversityCambridge, Massachusetts 02138

CONTENTS

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

ECONOMICS OF A COMPETITIVE ELECTRICITY MARKET . . . . . . . . . . . . . . . 2Short-Run Market. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Transmission Congestion.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Long-Run Market Contracts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Equivalent Transmission Interpretations. . . . . . . . . . . . . . . . . . . . . . . . . . 14Scheduling and Balancing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Long-Term Market Investment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Access Fees For Embedded Cost Recovery.. . . . . . . . . . . . . . . . . . . . . . . . 20Security Concerns and Capacity Reserves.. . . . . . . . . . . . . . . . . . . . . . . . 21

CONCLUSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

APPENDIXCompetitive Electricity Market Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

SHORT-RUN TRANSMISSION PRICING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Transmission Pricing Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

400 MW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26300 MW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27200 MW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27100 MW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Implications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

CONTRACT NETWORK EXAMPLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Economic Dispatch on a Grid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39Transmission Constraints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42Zonal Versus Nodal Pricing Approaches. . . . . . . . . . . . . . . . . . . . . . . . . . 48Transmission Congestion Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

COMPETITIVE ELECTRICITY MARKETS:A WHOLESALE PRIMER 1

William W. Hogan2

A short-term electricity market coordinated by a system operator providesa foundation for a competitive electricity market. Combined with long-termcontracts for generation and transmission congestion, the spot-market andcompetitive market pricing can support open access to the transmission grid.

INTRODUCTION

Electricity market restructuring emphasizes the potential for competition ingeneration and retail services, with operation of transmission and distribution wires as amonopoly. Network interactions complicate the design of the institutions and pricingarrangements for open access to the wires. The design of the institutions for thewholesale market can accommodate access for both wholesale and retail competitionwhile recognizing the special requirements of reliability in the transmission grid.

A pool-based, short-term electricity market coordinated by a system operatorprovides a foundation for building an open access system. Coordination through thesystem operator is unavoidable, and a bid-based spot-market built on the principles ofeconomic dispatch creates the setting in the wholesale market for competition among themarket participants. The associated locational prices define the opportunity costs oftransmission usage and support transmission rights without restricting the actual use ofthe system. A system of contracts can provide the connection between short-termoperations and long-term investment built on market incentives.

The key elements of the wholesale market design include:

• A short-term spot market with bid-based security-constrained economic dispatchcoordinated by the system operator.

• Spot-market transactions at market clearing locational prices to include marginal

1 This paper combines and updates introductory descriptions from previous papers by the author oncompetitive market design and transmission pricing.

2 Lucius N. Littauer Professor of Public Policy and Administration, John F. Kennedy School ofGovernment, Harvard University, and Senior Advisor, Putnam, Hayes & Bartlett, Inc. This paper draws on workfor the Harvard Electricity Policy Group and the Harvard-Japan Project on Energy and the Environment. The authoris or has been a consultant on electric market reform and transmission issues for British National Grid Company,GPU Inc. (and the Supporting Companies of PJM), GPU PowerNet Pty Ltd, Duquesne Light Company, ElectricityCorporation of New Zealand, National Independent Energy Producers, New York Power Pool, New York UtilitiesCollaborative, Niagara Mohawk Corporation, PJM Office of Interconnection, San Diego Gas & Electric Corporation,Transpower of New Zealand, Westbrook Power, Williams Energy Group, and Wisconsin Electric Power Company.The views presented here are not necessarily attributable to any of those mentioned, and any remaining errors aresolely the responsibility of the author. (http://ksgwww.harvard.edu/people/whogan).

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losses and congestion.

• Bilateral transactions with short-term transmission usage charges equal to thedifference in the locational prices at source and destination.

• A two settlement system using day-ahead bidding, pricing and contracts, withreal-time balancing at the real-time market prices.

• Transmission congestion contracts to allocate the benefits of transmission rights.

• Network access charges to cover the embedded costs of the grid and other fixedcharges.

• Usage charges for loads to recover other unbundled ancillary service costs.

A sketch of the details outlines the basic elements of the competitive market designthat would support both wholesale and retail transactions.

ECONOMICS OF A COMPETITIVE ELECTRICITY MARKET

A general framework that encompasses the essential economics of electricitymarkets provides a point of reference for evaluating market design elements. Thisframework for wholesale market provides the foundation for pricing and access, as wellas extension to retail competition.

Restructuring

Genco Genco Genco Genco Genco Genco

Poolco

GridcoGridco

Competitive Wholesale Electricity Market Structure

Gen

erat

ion

Tra

nsm

issi

onD

istr

ibut

ion

Regulated

Regulated

Disco Disco Disco Disco Disco Disco

Cust. Cust. Cust. Cust. Cust.Cust.

System Operator

of electricity mar-k e t s t y p i c a l l yemphasizes func-tional unbundlingof the verticallyintegrated system.The usual separa-tion into generation,transmission, anddistribution is insuf-ficient. In an elec-tricity market, thetransmission wiresand the pool dis-patch are distinctessential facilities.The special condi-tions in the electricity system stand as barriers to an efficient, large-scale market inelectricity. A pool-based market coordinated by a system operator helps overcome thesebarriers.

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Reliable operation is a central requirement and constraint for any electricity system.Given the strong and complex interactions in electric networks, current technology witha free-flowing transmission grid dictates the need for a system operator that coordinatesuse of the transmission system. Control of transmission usage means control of dispatch,which is the principal or only means of adjusting the use of the network. Hence, openaccess to the transmission grid means open access to the dispatch as well. There mustbe a system operator coordinating use of the transmission system. That this systemoperator should also be independent of the existing electric utilities and other marketparticipants is attractive in its simplicity in achieving equal treatment of all marketparticipants. The independent system operator provides an essential service, but does notbe compete in the energy market. In the analysis of electricity markets, therefore, a keyfocus is the design of the interaction between transmission and dispatch, both proceduresand pricing, to support a competitive market.

To provide an overview of the operation of an efficient, competitive wholesaleelectricity market, it is natural to distinguish between the short-run operations coordinatedby the system operator and long-run decisions that include investment and contracting.Under the competitive market assumption, market participants are price takers and includethe generators and eligible customers. For this discussion, distributors are included ascustomers in the wholesale market, operating at arm's length from generators. The systemis much simpler in the very short run when it is possible to give meaningful definitionto concepts such as opportunity cost. Once the short-run economics are established, thelong-run requirements become more transparent. Close attention to the connectionbetween short- and long-run decisions isolates the special features of the electricitymarket.

Short-Run Market.

The short run is a long time on the electrical scale, but short on human scale – say,half an hour. The short-run market is relatively simple. In the short run, locationalinvestment decisions have been made. Power plants, the transmission grid, anddistribution lines are all in place. Customers and generators are connected and the workof buyers, sellers, brokers and other service entities is largely complete. The onlydecisions that remain are for delivery of power, which in the short-run is truly acommodity product.3

3 On the electrical scale, much can happen in half an hour and the services provided by the systeminclude many details of dynamic frequency control and emergency response to contingencies. Due to transactioncosts, if nothing else, it would be inefficient to unbundle all of these services, and many are covered as average costsin the overhead of the system. How far unbundling should go is an empirical question. For example, real powershould be identified and its marginal cost recognized, but should this extend to reactive power and voltage controlas well? Or to spinning reserve required for emergency supplies? The costs associated with delivery of electricenergy include many services. The direct fuel cost of generation is only one component. In analyses of energypricing, there is no uniformity in the treatment of these other, ancillary services. The typical approach formulatesan explicit model approximating the full electricity system, computing both a dispatch solution and associated prices

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Over the half hour, the market operates competitively to move real power fromgenerators to customers. Generators have a marginal cost of generating real power fromeach plant, and customers have different quantities of demand depending on the price atthat half hour. The collection of generator costs stacks up to define the generation "meritorder," from least to most expensive. This merit order defines the short-run marginal-costcurve, which governs power supply. Similarly, customers have demands that are sensitiveto price, and higher prices produce lower demands. Market participants using bilateraltransactions provide schedules with any associated bids. Generators and customers donot act unilaterally; they provide information to the dispatcher to be used in a decisionprocess that will determine which plants will run at any given half hour. Power poolsprovide the model for achieving the most efficient dispatch given the short-run marginalcosts of power supply. Although dispatchable demand is not always included, there isnothing conceptually or technically difficult about this extension. The system operatorcontrols operation of the system to achieve the efficient match of supply and demandbased on the preferences of the participants as expressed in the bids.

This efficient

MW

Energy Price

($/mwH)

Q1 Q2 Qmax

Demand2-2:30 a.m.

Demand9-9:30 a.m.

Demand7-7:30 p.m.

Short-RunMarginal

Cost

Price at7-7:30 p.m.

Price at9-9:30 a.m.

Price at2-2:30 a.m.

Short-Run Electricity Marketcentral dispatch canbe made compatiblewith the marketoutcome. Thefundamental princi-ple is that for thesame load, theleast-cost dispatchand the competi-tive-market dispatchare the same. Theprincipal differencebetween the tradi-tional power pooland the marketsolution is the pricecharged to thecustomer. In the traditional power pool model, customers pay and generators receiveaverage cost, at least on average. However, as shown in the figure marginal cost

for the explicit variables. Everything that is not explicit is treated as an ancillary service, for which the assumptionmust be that the services will be provided and charged for in some way other than through the explicit prices in themodel. Given the complexity of the real electric system, such approximations or simplifications are found in everymodel, and there is always a boundary between the explicit variables modeled and the implicit variables that willbe treated as separate ancillary services. Payment for the ancillary services may be through an average cost upliftapplied to all loads. Development of a full description of the interactions with ancillary services is beyond the scopeof the present discussion. For the sake of the present discussion, focus on real power and assume that furtherunbundling would go beyond the point of diminishing returns in the short-run market.

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implicitly determines the least-cost dispatch, and marginal cost is the standard determinantof competitive market pricing.

An important distinction between the traditional central dispatch and thedecentralized market view is found in the source of the marginal-cost information for thegenerator supply curve. Typically, the cost data come from engineering estimates of theenergy cost of generating power from a given plant at a given time. However, relyingon these engineering estimates is problematic in the market model since the trueopportunity costs may include other features, such as the different levels of maintenance,that would not be captured in the fuel cost. Replacement of the generator’s engineeringestimates (that report only incremental fuel cost) with the generator’s market bids is thenatural alternative. Each bid defines the minimum acceptable price that the generatorwould accept to run the plant in the given half hour. And these bids serve as the guidefor the dispatch.

As long as the generator receives the market clearing price, and there are enoughcompetitors so that each generator assumes that it will not be determining the marginalplant, then the optimal bid for each generator is the true marginal cost: To bid morewould only lessen the chance of being dispatched, but not change the price received. Tobid less would create the risk of running and being paid less than the cost of generationfor that plant. Hence, with enough competitors and no collusion, the short-run centraldispatch market model can elicit bids from buyers and sellers. The system operator cantreat these bids as the supply and demand and determine the balance that maximizesbenefits for producers and consumers at the market equilibrium price. Hence, in the shortrun electricity is a commodity, freely flowing into the transmission grid from selectedgenerators and out of the grid to the willing customers. Every half hour, customers payand generators receive the short-run marginal-cost price for the total quantity of energysupplied in that half hour. Everyone pays or receives the true opportunity cost in theshort run. Payments follow in a simple settlement process.

Transmission Congestion.

This overview of the short-run market model is by now familiar and found inoperation in many countries. However, this introductory overview conceals a criticaldetail that would be relevant for transmission pricing. Not all power is generated andconsumed at the same location. In reality, generating plants and customers are connectedthrough a free-flowing grid of transmission and distribution lines.

In the short-run, transmission too is relatively simple. The grid has been built andeveryone is connected with no more than certain engineering requirements to meetminimum technical standards. In this short-run world, transmission reduces to nothingmore than putting power into one part of the grid and taking it out at another. Powerflow is determined by physical laws, but a focus on the flows – whether on a fictionalcontract path or on more elaborate allocation methods – is a distraction. The simplermodel of input somewhere and output somewhere else captures the necessary reality. In

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this simple model, transmission complicates the short-run market through the introductionof losses and possible congestion costs.

Transmission of power over wires encounters resistance, and resistance createslosses. Hence the marginal cost of delivering power to different locations differs at leastby the marginal effect on losses in the system. Incorporating these losses does not requirea major change in the theory or practice of competitive market implementation.Economic dispatch would take account of losses, and the market equilibrium price couldbe adjusted accordingly. Technically this would yield different marginal costs anddifferent prices, depending on location, but the basic market model and its operation inthe short-run would be preserved.

Transmission congestion has a related effect. Limitations in the transmission gridin the short run may constrain long-distance movement of power and thereby impose ahigher marginal cost in certain locations. In the simplest case, power will flow over thetransmission line from the low cost to the high cost location. If this line has a limit, thenin periods of high demand not all the power that could be generated in the low costregion could be used, and some of the cheap plants would be "constrained off." In thiscase, the demand would be met by higher cost plants that, absent the constraint, wouldnot run, but due to transmission congestion would be then "constrained on." Themarginal cost in the two locations differs because of transmission congestion. Themarginal cost of power at the low cost location is no greater than the cost of the cheapestconstrained-off plant at that location; otherwise the plant would run. Similarly, themarginal cost at the high cost location is no less than the cost of the most expensiveconstrained-on plant at that location; otherwise the plant would not be in use. Thedifference between these two costs, net of marginal losses, is the congestion rental.4

This congested-induced marginal-cost difference can be as large as the cost of thegeneration in the unconstrained case. If a cheap coal plant is constrained off and an oilplant, which costs more than twice as much to run, is constrained on, the difference inmarginal costs by region is greater than the cost of energy at the coal plant. This resultdoes not depend in any way on the use of a simple case with a single line and twolocations. In a real network, the interactions are more complicated – with loop flow andmultiple contingencies confronting thermal limits on lines or voltage limits on buses – butthe result is the same. It is easy to construct examples where congestion in thetransmission grid leads to marginal costs that differ by more than 100% across differentlocations.

If there is transmission congestion, therefore, the short-run market model anddetermination of marginal costs must include the effects of the constraints. This extensionpresents no difficulty in principle. The only impact is that the market now includes a set

4 Losses are not always negligible and could be treated explicitly. However, it would add nothing to thediscussion here. At locations distant from the constrained off or constrained on plants, prices can vary even moreas it may be necessary to increase the use of expensive plants and decrease the use of cheap plants in combinationsthat create opportunity costs greater than the cost of any single plant.

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of prices, one for each location. Economic dispatch would still be the least-costequilibrium. Generators would still bid as before, with the bid understood to be theminimum acceptable price at their location. Customers would bid also, with dispatchabledemand and the bid setting the maximum price that would be paid at the customer’slocation. The economic dispatch process would produce the corresponding prices at eachlocation, incorporating the combined effect of generation, losses and congestion. In termsof their own supply and demand, everyone would see a single price, which is thelocational marginal cost based price of power at their location. If a transmission priceis necessary, the natural definition of transmission is supplying power at one location andusing it at another. The corresponding transmission price would be the differencebetween the prices at the two locations.

This same framework lends itself easily to extensions including bilateraltransactions. If market participants wish to schedule transmission between two locations,the opportunity cost of the transmission is just this transmission price of the differencebetween spot prices at the two locations. This short-run transmission usage pricing,therefore, is efficient and non-discriminatory. In addition, the same principles could applyin a multi-settlement framework, with day-ahead scheduling and real-time dispatch.These extensions could be important in practice, but would not fundamentally change theoutline of the structure of electricity markets.

This short-run competitive market with bidding and centralized dispatch isconsistent with economic dispatch. The locational prices define the true and fullopportunity cost in the short run. Each generator and each customer sees a single pricefor the half hour, and the prices vary over half hours to reflect changing supply anddemand conditions. All the complexities of the power supply grid and networkinteractions are subsumed under the economic dispatch and calculation of the locationalprices. These are the only prices needed, and payments for short-term energy are the onlypayments operating in the short run, with administrative overhead covered by rents onlosses or, if necessary, a small markup added to the cost of ancillary services and appliedto all load. The system operator coordinates the dispatch and provides the informationfor settlement payments, with regulatory oversight to guarantee comparable servicethrough open access to the pool run by the system operator through a bid-based economicdispatch.

With efficient pricing, users have the incentive to respond to the requirements ofreliable operation. Absent such price incentives, the system operator would be requiredto restrict choice and limit the market, in order to give the system operator enough controlto counteract the perverse incentives that would be created by prices that did not reflectthe marginal costs of dispatch. A competitive market with choice and customer flexibility

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depends on getting the usage pricing right.

Long-Run Market Contracts.

With changing supply and demand conditions, generators and customers will seefluctuations in short-run prices. When demand is high, more expensive generation willbe employed, raising the equilibrium market prices. When transmission constraints bind,congestion costs will change prices at different locations.

Even without transmission congestion constraints, the spot market price can bevolatile. This volatility in prices presents its own risks for both generators and customers,and there will be a natural interest in long-term mechanisms to mitigate or share this risk.The choice in a market is for long-term contracts.

Traditionally, and in many other markets, the notion of a long-term contract carrieswith it the assumption that customers and generators can make an agreement to trade acertain amount of power at a certain price. The implicit assumption is that a specificgenerator will run to satisfy the demand of a specific customer. To the extent that thecustomer’s needs change, the customer might sell the contract in a secondary market, andso too for the generator. Efficient operation of the secondary market would guaranteeequilibrium and everyone would face the true opportunity cost at the margin.

However, this notion of specific performance stands at odds with the operation ofthe short-run market for electricity. To achieve an efficient economic dispatch in theshort-run, the dispatcher must have freedom in responding to the bids to decide whichplants run and which are idle, independent of the provisions of long-term contracts. Andwith the complex network interactions, it is impossible to identify which generator isserving which customer. All generation is providing power into the grid, and allcustomers are taking power out of the grid. It is not even in the interest of the generatorsor the customers to restrict their dispatch and forego the benefits of the most economicuse of the available generation. The short-term dispatch decisions by the system operatorare made independent of and without any recognition of any long-term contracts. In thisway, electricity is not like other commodities.

This dictate of the physical laws governing power flow on the transmission griddoes not preclude long-term contracts, but it does change the essential character of thecontracts. Rather than controlling the dispatch and the short-run market, long-termcontracts would focus on the problem of price volatility and provide a price hedge not bymanaging the flow of power but by managing the flow of money. The short-run pricesprovide the right incentives for generation and consumption, but create a need to hedgethe price changes. Recognizing the operation of the short-run market, there is aneconomic equivalent of the long-run contract for power that does not require any specificplant to run for any specific customer.

Consider the case first of no transmission congestion. In this circumstance, exceptfor the small effect of losses, it is possible to treat all production and consumption as atthe same location. Here the natural arrangement is to contract for the deviation from the

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equilibrium price in the market. A customer and a generator agree on an average pricefor a fixed quantity, say 100 MW at five cents. On the half hour, if the pool price is sixcents, the customer buys power from the pool at six cents and the generators sells powerfor six cents. Under the contract, the generator owes the customer one cent for each ofthe 100 MW over the half hour. In the reverse case, with the pool price at three cents,the customer pays three cents to the system operator, which in turn pays three cents tothe generator, but now the customer owes the generator two cents for each of the 100MW over the half hour. Familiar in other commodity industries, this is known in theelectricity market as a "contract for differences."

In effect, the generator and the customer have a long-term contract for 100 MWat five cents. The contract requires no direct interaction with system operator other thanfor the continuing short-run market transactions. But through the interaction with systemoperator, the situation is even better than with a long-run contract between a specificgenerator and a specific customer. For now if the customer demand is above or below100 MW, there is a ready and an automatic secondary market, namely the pool, whereextra power is purchased or sold at the pool price. Similarly for the generator, there isan automatic market for surplus power or backup supplies without the cost and problemsof a large number of repeated short-run bilateral negotiations with other generators. Andif the customer really consumes 100 MW, and the generator really produces the 100 MW,the economics guarantee that the average price is still five cents. Furthermore, with thecontract fixed at 100 MW, rather than the amount actually produced or consumed, thelong-run average price is guaranteed without disturbing any of the short-run incentivesat the margin. Hence the long-run contract is compatible with the short-run market.

The price of the generation contract would depend on the agreed reference priceand other terms and conditions. Generators and customers might agree on dead zones,different up-side and down-side price commitments, or anything else that could benegotiated in a free market to reflect the circumstances and risk preferences of the parties.Whether generators pay customers, or the reverse, depends on the terms. However,system operator need take no notice of the contracts, and have no knowledge of the terms.Such contracts for differences have become common in restructured electricity markets.

In the presence of transmission congestion, the generation contract is necessary butnot sufficient to provide the necessary long-term price hedge. A bilateral arrangementbetween a customer and a generator can capture the effect of aggregate movements in themarket, when the single market price is up or the single market price is down. However,transmission congestion can produce significant movements in price that are differentdepending on location. If the customer is located far from the generator, transmissioncongestion might confront the customer with a high locational price and leave thegenerator with a low locational price. Now the generator alone cannot provide the naturalback-to-back hedge on fluctuations of the short-run market price. Something more isneeded.

Transmission congestion in the short-run market raises another related andsignificant matter for the system operator. In the presence of congestion, revenues

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collected from customers will substantially exceed the payments to generators. Thedifference is the congestion rent that accrues because of constraints in the transmissiongrid. At a minimum, this congestion rent revenue itself will be a highly volatile sourceof payment to the system operator. At worse, if the system operator keeps the congestionrevenue, incentives arise to manipulate dispatch and prevent grid expansion in order togenerate even greater congestion rentals. System operation is a natural monopoly and theoperator could distort both dispatch and expansion. If the system operator retains thebenefits from congestion rentals, this incentive would work contrary to the goal of anefficient, competitive electricity market.

A convenient solution for both problems – providing a price hedge againstlocational congestion differentials and removing the adverse incentive for the systemoperator – is to re-distribute the congestion revenue through a system of long-runtransmission congestion contracts operating in parallel with the long-run generationcontracts. Just as with generation, it is not possible to operate an efficient short-runmarket that includes transmission of specific power to specific customers. However, justas with generation, it is possible to arrange a transmission congestion contract thatprovides compensation for differences in prices, in this case for differences in thecongestion costs between different locations across the network.

As illustrated

DEFINE TRANSMISSION CONGESTION CONTRACTS BETWEEN LOCATIONS.

FOR SIMPLICITY, TREAT LOSSES AS OPERATING COSTS.

RECEIVE CONGESTION PAYMENTS FROM ACTUAL USERS; MAKECONGESTION PAYMENTS TO HOLDERS OF CONGESTION CONTRACTS.

Bus Price = Generation Cost + Marginal Losses + Congestion Costs

Pa = 5.15

Pc = 5.00

Pb = 5.30 + 1.95 = 7.25

A

C

B

TRANSMISSION CONGESTION CONTRACTS PROVIDE PROTECTION

Pcb = Pb - Pc = Marginal Losses + Congestion Costs = 0.3 + 1.95 = 2.25

Constrained Interface

AGAINST CHANGING LOCATIONAL DIFFERENCES.

NETWORK TRANSMISSION CONGESTION CONTRACTSin the figure, atransmission con-gestion contractdefines a hedge ford i f f e rences inlocational prices.Everyone who usesthe transmissionsystem pays accord-ing to the spot-market locationalprices. For exam-ple, generation at Areceives 5.15 cents.Load at B pays7.25 cents, with theprice includingmarginal losses and congestion. Transmission between C and B would pay 2.25 cents.Included in this transmission charge would be a congestion payment of 1.95 cents. Atransmission congestion contract between C and B would result in a payment of the 1.95cents to the holder of the contract. Hence, if the participant actually transported thepower, the transmission congestion contract would just balance the congestion charge forthe quantity covered by the contract. And if the holder of the transmission congestioncontract does not transport power, the result is the same as selling the transmission right

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to the actual user.

The transmission congestion contract for compensation would exist for a particularquantity between two locations. A generator at location C might obtain a transmissioncongestion contract for 100 MW between the generator’s location and the customer atlocation B. The right provide by the contract would not be for specific movement ofpower but rather for payment of the congestion rental. Hence, ignoring losses, if atransmission constraint caused prices to rise to 6.95 cents at the customer’s location, butremain at five cents at the generator’s location, the 1.95 cents difference would be thecongestion rental. The customer would pay the pool 6.95 cents for the power actuallytaken. The pool would in turn pay the generator five cents for the power supplied in theshort-run market. As the holder of the transmission congestion contract, the generatorwould receive 1.95 cents for each of the 100 MW covered under the transmissioncongestion contract. The generation and the load would see the right incentives on themargin. The transmission congestion contract revenue would allow the generator to paythe difference under the generation contract so that the net cost to the customer is fivecents as agreed in the bilateral power contract. Without the transmission congestioncontract, the generator would have no revenue to compensate the customer for thedifference in the prices at their two locations. The transmission congestion contractcompletes the package described as a "contract network."

Note that the transmission congestion contract is defined as a point-to-pointcomparison of locational prices. There is no reference to the individual transmission linksor the path by which the power may move between two points. This is an importantdistinction that separates the transmission congestion contract from "link-based" rights thatotherwise confront difficult anomalies and perverse incentives. For example, it is entirelypossible to construct examples of valuable transmission links that have no net power flow,making them appear worthless for many definitions of link-based rights. But thiscondition would not impact the definition or the value of transmission congestioncontracts.

The allocation of transmission congestion contracts among market participantscould arise in many ways. For a market in transition during a restructuring process, theallocation might be intended to reflect explicit or implicit historical rights. For newtransmission, there could be a negotiation process to select and award one of the manypossible combinations of feasible contracts. In addition, some or all of the transmissioncongestion contracts for the grid could be defined and awarded through an open auction.The collective bids would define demand schedules for contracts. The concurrent auctionwould respect the transmission system constraints to assure simultaneous feasibility.

For example, the accompanying figure illustrates a hypothetical auction with twodemand curves for transmission congestion contracts on a simple network with three

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locations. The

Concurrent Auction of Transmission Congestion Contracts

1 3

2

TCCs from 1 -> 3 awarded for 480 MW at price 3.6TCCs from 2 -> 3 awarded for 840 MW at price 1.8

TCC Bids1-3

TCC Bids2-3

optimal award thatm a x i m i z e sthe benefit5 of thecontracts includes480 MW from bus1 to bus 3 and 840MW from bus 2 tobus 3.

With spotmarket locationalprices, the transmis-sion congestioncontracts provideprice protection.Even with changingload patterns, thecongestion revenuescollected by the system operator will be at least enough to cover the obligations for allthe contracts.

Consider a

Constraints with Out-Of-Merit Costs

1 3

2

typical dispatchwith the transmis-sion constraintbinding. Supposethe solution is as inthe accompanyingfigure, with a totalload of 3000 MWat bus 3. Thegeneration at bus 3accounts for 2100MW, with thebalance of 900 MWcoming from bus 1.The assumed mar-ket clearing pricesat buses 1 and 3 are2 cents and 2.6 cents, respectively. From these prices, and the knowledge that there is

5 The benefit is defined as the consumer welfare, the area under the demand curves. Note this is not thesame as the value of the transmission congestion contracts at the market clearing price. The model is the simplifiedDC-Load model.

13

only one binding transmission constraint, we can compute the implied equilibrium pricesat all other buses.6 In this case bus 2 has a price of 2.3 cents. Note that the marketequilibrium for this dispatch is quite different from the pattern of flows envisioned in theallocation of the transmission congestion contracts. However, the different pattern of use,and the associated spot prices, present no difficulty for the system operator. As along asthe allocation of the transmission congestion contracts defines a set of inputs and outputsthat would be simultaneously feasible, then the revenue collected from the spot prices forcongestion will be sufficient to compensate the holders of the contracts for the obligationsat the same set of spot prices.7

The resulting calculation is illustrated in the accompanying table. The paymentobligations for the inputs and outputs at the spot prices define a set of net payments forthe actual loads. The payment obligations for the transmission congestion contracts equalthe net revenues.

System Operator Revenues

Quantity Price $

Bus 1 900 2 ($1,800)

Bus 2 0 2.3 $0

Bus 3 2100 2.6 ($5,460)

Bus 3 -3000 2.6 $7,800

TCC 1-3 480 0.6 ($288)

TCC 2-3 840 0.3 ($252)

Net Total $0

In effect, the system operator collects the congestion rents from the users of thesystem and distributes these same rents to the holders of the transmission congestioncontracts. In this case, with the simplified assumptions and the same binding constraint,the payments exactly balance. In general, excess congestion rents may remain afterpaying all obligations under the transmission congestion contracts. These excess rentals

6 William W. Hogan E. Grant Read, and Brendon J. Ring, "Using Mathematical Programming forElectricity Spot Pricing," International Transactions in Operational Research, Vol. 3, No. 3/4, 1996, pp. 209-221.

7 For a further discussion of power flows and spot pricing, see William W. Hogan, "Contract Networksfor Electric Power Transmission," Journal of Regulatory Economics, Vol. 4, 1992, p. 214.

14

should not remain with the system operator, but could be distributed according to somesharing formula to those paying the fixed costs of the existing grid or along with thepayments under transmission congestion contracts.8 Many variants are possible, allowinggreat flexibility in developing and trading contracts. The contract network can allow greatcommercial flexibility while respecting the reality of the actual network in determiningthe locational prices.

When only the single generator and customer are involved, this sequence ofexchanges under the two types of contracts may seem unnecessary. However, in a realnetwork with many participants, the process would be far less obvious. There will bemany possible transmission combinations between different locations. There is no singledefinition of transmission grid capacity, and it is only meaningful to ask if theconfiguration of allocated transmission flows is feasible. However, the net result wouldbe the same. Short-run incentives at the margin follow the incentives of short-runopportunity costs, and long-run contracts operate to provide price hedges against specificquantities. The system operator coordinates the short-run market to provide economicdispatch. The system operator collects and pays according to the short-run marginal priceat each location, and the system operator distributes the congestion rentals to the holdersof transmission congestion contracts. Generators and customers make separate bilateralarrangements for generation contracts. Unlike with the generation contracts, the systemoperator's participation in coordinating administration of the transmission congestioncontracts is necessary because of the network interactions, which make it impossible tolink specific customers paying congestion costs with specific customer receivingcongestion compensation. If a simple feasibility test is imposed on the transmissioncongestion contracts awarded to customers, the aggregate congestion payments receivedby the system operator will fund the congestion payment obligations under thetransmission congestion contracts. Still, the congestion prices paid and received will behighly variable and load dependent. Only the system operator will have the necessaryinformation to determine these changing prices, but the information will be readilyavailable embedded in the spot market locational prices. The transmission congestioncontracts define payment obligations that guarantee protection from changes in thecongestion rentals.

Equivalent Transmission Interpretations.

The transmission congestion contract can be recognized as equivalent to anadvantageous form of point-to-point “physical” transmission right. Were it possible todefine usage of the transmission system in terms of physical rights, it would be desirablethat these rights have two features.

First, they could not be withheld from the market to prevent others from using the

8 The allocation of excess congestion rentals is part of the specification of the transmission congestioncontracts. Although important in practice, it would have little impact on the present analysis.

15

transmission grid.

TradableCapacity

Reservations

OpportunityCostPricing

Transmission Congestion Contracts

Transmission Capacity Reservations & Congestion Contracts

Financial Perspective

Physical Perspective

Second, they wouldb e p e r f e c t l yt radable in asecondary marketthat would supportfull reconfigurationof the patterns ofnetwork use, at notransaction cost.This is impossiblewith any knownsystem of physicaltransmission rightsthat parcel up thetransmission grid.However, in ac o m p e t i t i v eelectricity market with a bid-based economic dispatch, transmission congestion contractsare equivalent to just such perfectly tradable transmission rights.

With a competitive market and tradable physical transmission capacity reservations,any use of the system not matched by a reservation would be settled at opportunity costprices determined by the final dispatch or actual use of the system. Trading of physicaltransmission capacity reservations must be coordinated through the system operator.Under competitive conditions, the price that would be paid for transmission capacitywould be the opportunity cost, which is the same as the difference in the locational prices.If there were no transaction costs, therefore, this physical perspective would beindistinguishable from the financial perspective of transmission congestion contracts basedon the same opportunity cost.

The physical perspective may be more intuitive. The financial perspective withtransmission congestion contracts as perfectly tradeable rights is easier to implement andhas lower transaction costs.

Hence, we can describe transmission congestion contracts either as financialcontracts for congestion rents or as perfectly tradable point-to-point physical transmissionrights. If the capacity for transmission congestion contracts has been fully allocated, thenthe system operator will be simply a conduit for the distribution of the congestion rentals.The operator would have no incentive to increase congestion rentals: any increase incongestion payments would flow only to the holders of the transmission congestioncontracts. The problem of supervising the dispatch monopoly would be greatly reduced.And through a combination of generation contracts and transmission congestion contracts,participants in the electricity market can arrange price hedges that could provide theeconomic equivalent of a long-term contract for specific power delivered to a specificcustomer.

16

Further to

EconomicDispatch

TransmissionTrading

Energy

Bidding

Opp

ortu

nity

Cos

t

Pric

ing

Genco Genco Genco Genco Genco Genco

PoolcoGridcoGridco

Disco Disco Disco Disco Disco Disco

Cust. Cust. Cust. Cust. Cust.Cust.

System Operator

Coordinated Transmission Trading Is Economic Dispatch

Financial Perspective

Physical Perspective

the application oft h e s e i d e a s ,locational marginalcost pricing lendsitself to a naturaldecomposition. Forexample, even withloops in a network,market informationcould be trans-formed easily into ah u b - a n d - s p o k eframework withlocational pricedifferences on aspoke defining thecost of moving toand from the local hub, and then between hubs. This would simplify without distortingthe locational prices. As shown in the figure, a contract network could develop thatwould be different from the real network, without affecting the meaning or interpretationof the locational prices.

With market

Contract Network Connects with Real Network

Real Network

Contract Network

Zonal Hub

Local Bus

Determine Locational Prices for Real Network; ImplementTransmission Congestion Contracts and Trading on Contract Network

hubs, the partici-pants would see thesimplification ofhaving a few loca-tions that capturemost of the pricedifferences of long-distance transmis-sion. Contractscould develop rela-tive to the hubs.The rest of thesometimes impor-tant difference inlocational priceswould appear in thecost of movingpower to and from the local hub. Commercial connections in the network could followa configuration convenient for contracting and trading. The separation of physical andfinancial flows would allow this flexibility.

17

Creation or elimination of hubs would require no intervention by regulators or thesystem operator. New hubs could arise as the market requires, or disappear when notimportant. A hub is simply a special node within a zone. The system operator stillwould work with the locational prices, but the market would decide on the degree ofsimplification needed. However, everyone would still be responsible for the opportunitycost of moving power to and from the local hub. There would be locational prices andthis would avoid the substantial incentive problems of averaging prices. The hub-and-spoke approach appears to give most of the benefits attributed to zones without the costs,and it implies that the system operator works within a locational pricing framework.

A version of this hub-and-spoke system appeared in the market launched in thePennsylvania-New jersey-Maryland (PJM) system in April 1998. Although the marketparticipants could create hubs without the participation of the system operator, there wasa popular request that the system operator identify and post hub prices. In order to reducethe price volatility that might be present in selecting a single location as a hub, the systemoperator responded to the request to create hubs consisting of a fixed-weight average ofa number of underlying locations. Hence, purchases and sales at the hub are equivalentto a portfolio of purchases and sales at the underlying locations, with the portfoliocomposition in terms of the fixed weights. Likewise, transmission between any locationand the hub is the equivalent of transmission between the given location and the portfolioof locations that make up the hub. This system is working now.

Scheduling and Balancing.

Implementation of the short-run dispatch market could take many forms. Inprinciple, the coordinated dispatch might be left to only the final hour, with all othercommitments and trades developed through decentralized transactions, notifying thesystem operator of the schedules only in time to complete the final balancing. At theother extreme, with long lead times for changing the configuration of generation or thepatterns of loads, it might be preferred to include unit commitment decisions over weeksor even longer periods.

In practice, most countries or regions adopt or recommended a procedure that fallssomewhere in between these alternatives. A two-settlement system with day-ahead bidsis especially attractive in providing greater opportunity for participation by flexibledemand without requiring real-time dispatch capabilities. The system operator acceptsbids and nominations for scheduled dispatch, say for a day ahead, and determines anappropriate market clearing equilibrium and associated payment settlements. Thisschedule then defines a set of commitments for delivering and taking power in the short-run dispatch. In the event, the actual dispatch will differ from the scheduled commit-ments, and appropriate balancing settlements would be arranged.

These connected scheduling and balancing settlements present no major difficulties,but there are a few points that need clarification to maintain consistent payments and in-centives. The basic schematic appears in the accompanying figure. Participants in the

18

market submi t

Price

Expected Load

S

D

Day-AheadSpot Price

(Day-Ahead)

NotifiedBilateralTrades

Notified bilateral trades pay locational transmission

Other trades settle at day-ahead pricecharge but are settled outside pool

Price

Expected Load

S

D Hi

(Day-Ahead)

D Lo

Priceif LowerDemand

Priceif HigherDemand

Payments for deviations from day-ahead trades

Uplift covers ancillary services and other costsat balancing price for all transactions

Scheduling Transactions Balancing Transactions

Balancing Price for Deviations from Scheduled Commitments

Locational congestion rents paid under transmission Excess congestion costs paid to holderscongestion contracts along with excess congestion costs of transmission congestion contracts

scheduling bids forthe day ahead forboth supply anddemand. Thesebids may includestart up costs,ramping rates andany of range ofplant and loadcharacteristics. Thesystem operatorutilizes all thisinformat ion todefine a least-costdispatch over theday that matchesscheduled load andgeneration. The results is a set of market clearing prices (P) and quantities (Q) thatdefine the schedule. In addition, the system operator arranges for any necessary reliabilitycommitments, such as for spinning and standby reserves to meet any expected deviationsin load from the day ahead schedules.

The equilib-

MW

¢

Start up Costs +

Generators&

Customers

...

TransmissionCongestion

T

DispatchCommitments

Q

SchedulingSettlements

P, Q, T

BalancingSettlements

p, q, Q

kWh $

kWh $

LocationalP, Q

Locationalp, q

Schedule BidsSchedules

Balancing Bids

Contract$

Q

Q

ExcessCongestion

$

ExcessCongestion

$T

Imbalance$

Scheduling Transactions

Balancing Transactions

Settlements

A Structure for Spot Market Dispatch & Settlements

MW

¢

MW

¢

MW

¢

ReliabilityCommitments

Contracts

rium prices andquantities differ bylocation and repre-sent immediate firmc o m m i t m e n t s .Based on thesecommitments, pay-ments would bemade through asettlements process.Conceptually thesesettlements couldoccur the minutethe schedule isdetermined; inpractice, the settle-ments would occurafter the fact. However, to preserve the consistency of the incentives and payments, thesettlements must be based on the scheduling prices and quantities. These settlements willinclude payments under long-term transmission congestion contracts shown by the symbol"T" in the schematic. Holders of transmission congestion contracts would receive or pay

19

the appropriate amounts of congestion cost differentials between locations for thecontracted quantity under the transmission congestion contract. Under some fixed sharingrule, the transmission congestion contract holders, or the presumptive parties responsiblefor paying the fixed charges of the transmission grid, would also share in any excesscongestion payments after settlement of the locational differences.

The schedule and the associated dispatch commitments (Q) would provide thereference point for the actual dispatch. In principle, bids in the scheduling market couldbe revised to create balancing bids for increments and decrements against the dispatchcommitments. Again the system operator would find the least-cost dispatch, hour byhour, based on the actual conditions and the final balancing bids. The result would bean actual dispatch with associated equilibrium prices (p) and quantities (q). These pricesand quantities would differ to a degree from the schedules, with the "imbalances" (q-Q)settled at the balancing price of "p". In this balancing settlements, the dispatchcommitments are conceptually similar to the transmission congestion contracts that applyin the scheduling settlements. And just as for the transmission congestion contracts, aftersettling all the imbalances at the market clearing price "p", there could be some excesscongestion payments that would be disbursed to the users and not kept by the systemoperator. In part, this excess would be used to reduce user payments for overhead andancillary services, not shown in the schematic, or rebated again to those who bear thefixed costs of the grid.

The precise treatment of the excess congestion rentals is not important, other thanto disburse them to the users and not the system operator in a way that creates noincentives for an inefficient dispatch. What is important, however, is to settle thescheduling markets and balancing markets with their own internally consistent prices (P,p)and quantities (Q,q). This is required, for example, to avoid the initial over-the-daygaming problems created in England and Wales by settling based on scheduled prices (P)and actual quantities (q).

Long-Term Market Investment.

Within the contract environment of the competitive electricity market, newinvestment occurs principally in generating plants, customer facilities and transmissionexpansions. In each case, corresponding contract-right opportunities appear that can beused to hedge the price uncertainty inherent in the operation of the competitive short-runmarket.

In the case of investment in new generating plants or consuming facilities, theprocess is straightforward. Under the competitive assumption, no single generator orcustomer is a large part of the market, there are no significant economies of scale, andthere are no barriers to entry. Generators or customers can connect to the transmissiongrid at any point subject only to technical requirements defining the physical standardsfor hookup. If they choose, new customers or new generators have the option of relyingsolely on the short-run market, buying and selling power at the locational price

20

determined as part of the half-hourly dispatch. The system operator makes no guaranteesas to the price at the location. The system operator only guarantees open access to thepool at a price consistent with the equilibrium market. The investor takes all the businessrisk of generating or consuming power at an acceptable price.

If the generator or customer wants price certainty, then new generation contractscan be struck between a willing buyer and a willing seller. The complexity and reach ofthese contracts would be limited only by the needs of the market. Typically we expecta new generator to look for a customer who wants a price hedge, and for the generatorsto defer investing in new plant until sufficient long-term contracts with customers can bearranged to cover a sufficient portion of the required investment. The generationcontracts could be with one or more customers and might involve a mix of fixed chargescoupled with the obligations to compensate for price differences relative to the spot-market price. But the customer and generator would ultimately buy and sell power attheir location at the half-hourly price.

If either party expects significant transmission congestion, then a transmissioncongestion contract would be indicated. If transmission congestion contracts are for salebetween the two points, then a contract can be obtained from the holder(s) of existingrights. Or new investment can create new capacity that would support additionaltransmission congestion contracts. The system operator would participate in the processonly to verify that the newly created transmission congestion contracts would be feasibleand consistent with the obligation to preserve any existing set of transmission congestioncontracts on the existing grid. Unlike the ambiguity in the traditional definition oftransmission transfer capacity, there is a direct test to determine the feasibility of any newset of transmission congestion contracts for compensation–while protecting the existingrights–and the test is independent of the actual loads that may develop. Hence,incremental investments in the grid would be possible anywhere without requiring thateveryone connected to the grid participate in the negotiations or agree to the allocationof the new transmission congestion contracts.

Access Fees For Embedded Cost Recovery.

There are substantial economies of scale in transmission expansion.9 The totalcongestion revenue from transmission usage charges, therefore, generally would be lessthan the cost of the grid. This means that transmission pricing cannot rely solely oncongestion payments to recover the full costs of the existing transmission grid. The

9 Ross Baldick and Edward Kahn, "Network Costs and the Regulation of Wholesale Competition inElectric Power," Journal of Regulatory Economics, Vol. 5, 1993, pp. 37-384. The problems created by economiesof scale are addressed in the context of transmission pricing in the New Zealand by E. G. Read and D. P. M. Sell,"Pricing and Operation of Transmission Services: Short Run Aspects," Report to Trans Power, Canterbury Universityand Arthur Young, New Zealand, October 1988; E. G. Read, "Pricing of Transmission Services: Long RunAspects," Report to Trans Power, Canterbury University, New Zealand, October 1988; E. G. Read and D. P. M.Sell, "A Framework for Transmission Pricing," Report to Trans Power, Arthur Young, New Zealand, December 1988.

21

incentive of avoiding future congestion payments may prompt transmission investment,but the ex post congestion payments could be lower after the investment. Hence, thecompetitive market model outline here relies on pricing according to two-part pricesincluding a fixed and variable charge. This approach contrasts with the alternative of aone-part transmission charge with a single price based on usage. Application of two-partprices is especially apt in the case of transmission, where it is difficult to produce anacceptable definition of use that is tied to any subset of the network. Any attempt torecover all or some of the fixed costs of the network based on variable charges confrontsthe problem of defining who is using which facility, and why. In a free-flowing electricaltransmission grid, power may flow in ways that are beyond the control or intent of theuser. And if as can be the case, the short-run opportunity costs are significantly differentthan some pro-rata allocation of the long-run capital costs, a one-part tariff that averagesfixed costs along with variable costs can produce inefficient incentives and contentiousdebate over complex and changing allocations. However, in the competitive marketmodel outlined here these problems for transmission are handled through the effectiveapplication of a two-part price. Short-run variable costs of transmission use are paidthrough the automatic pricing of the pool operations. Long-run fixed charges are agreedto under contract as part of the process of deciding on new investments in the grid.

The access fees can differ by location, but would be under the "license plate"model. Customers would pay only once for access to the grid. Prices for actual use ofthe grid would based in locational opportunity costs in the spot market.

Security Concerns and Capacity Reserves.

Secure economic dispatch coordinated through the system operator respects thecurrent contingency limits on power flows and generation limits. In the short-run, theeffect of security constraints in the system is to limit transmission and force out-of-meritgeneration which gives rise to short-run congestion costs. These short-run marginal costsare the true opportunity costs of "security," and in the competitive market customers facethese opportunity costs. In the long-run, investment in the grid is undertaken whencustomers find it economic to reduce these congestion costs and the cost of losses. In thissense, evolution of the grid would be determined by the market. Since all demand isalways met, at the short-run locational marginal cost, there is no non-price curtailment ofdemand and no need to build excess capacity to provide a reserve margin. There may behigh prices at times, and price will rise until demand can be met at marginal cost. Butthere is no separate or additional security or reliability problem. Hence, security in theshort-run is maintained through the security constrained dispatch, and security in the long-run is priced and provided through the market for long-run investments to increasegeneration and transmission capacity.

22

CONCLUSION

A pool-based, short-term electricity market coordinated by a system operatorprovides a foundation for building a wholesale market with open access and tradeabletransmission property rights in the form of transmission congestion contracts.Coordination through the system operator is unavoidable, and spot-market locationalprices define the opportunity costs of transmission that would determine the market valueof the transmission rights without requiring physical trading and without restricting theactual use of the system. In this setting, these transmission congestion contracts areequivalent to perfectly tradeable physical rights.

23

APPENDIX

Competitive Electricity Market Pricing

INTRODUCTION

Examples of pricing in networks illustrate the issues and the use of least-costdispatch with accompanying transmission congestion contracts under the pool-basedmodel.10 Pricing in a competitive electricity market is at marginal cost. The manypotential suppliers compete to meet demand, bidding energy supplies into the pool. Thedispatchers choose the least-cost combination of generation or demand reductions tobalance the system. This optimal dispatch determines the market clearing prices.Consumers pay this price into the pool for energy taken from the spot market andgenerators in turn are paid this price for the energy supplied.

Inherently, energy pricing and transmission pricing are intimately connected. TheFERC has outlined objectives for transmission pricing that would be compatible with acompetitive market.11 A series of examples of pricing in the competitive electricitymarket model illustrates the determination of prices under economic dispatch in a networkand relates transmission constraints to congestion rentals that lead to different prices atdifferent locations. These fundamentals provide the building blocks for an energy andtransmission pricing system that addresses the several requirements of the FERC outline.

SHORT-RUN TRANSMISSION PRICING

A system operator (SO) can implement a pricing regime to support the competitivemarket. This pricing and access regime can accommodate both a pool-based spot marketand more traditional "physical" bilateral contracts. The key is in how the SO providesbalancing services, adjusts for transmission constraints and charges for transmission usage.The SO would match buyers and sellers in the short-term market. The SO would receive"schedules" that could include both quantity and bidding information. For the participantsin the pool, these schedule-bids would be for loads or generation with maximum orminimum acceptable prices. For the self-nominations of bilateral transactions, theschedule-bids would be for transmission quantities with increment and decrement bids forboth ends of the transaction. These incremental and decremental bids would apply only

10 These examples illustrate the elements of locational marginal cost pricing. They are adapted from W.Hogan, "A Wholesale Pool Spot Market Must Be Administered by the Independent System Operator: Avoiding theSeparation Fallacy," The Electricity Journal, December 1995, pp. 26-37; W. Hogan "Transmission Pricing andAccess Policy for Electricity Competition," The Harvard-Japan Project on Energy and the Environment, February1996.

11 Federal Energy Regulatory Commission, "Transmission Pricing Issues," Staff Discussion Paper, InquiryConcerning the Commission’s Pricing Policy for Transmission Services Provided by Public Utilities Under theFederal Power Act, Washington, DC, June 1993, pp. 7-8.

24

for the short-term dispatch and need not be the same as the confidential bilateral contractprices.

The responsibility of the SO would be to integrate the schedules and the associatedbids for deviations from the schedules to find the economic combination for all marketparticipants. This range of schedule-bids would be more varied and flexible, givingeveryone more choices.

Transmission Pricing Examples

A set of examples can illuminate the treatment of spot-market transactions andbilateral transactions, under the SO’s responsibility to achieve an economic dispatch.These examples are simple, but they capture the essential points in terms of thealternatives available for bilateral transactions. The test of no conflict of interest and non-discrimination is that, other things being equal, there should be no incentive in thedispatch or pricing mechanism to favor either the spot market or the bilateral transaction.

For simplicity, we ignore here any complications of market power or long-run

Transmission with Pool Bids and Bilateral Transactions

A B

Gen. BidsGen. Bids

Bilateral Transactions from A to B

Constrained Transmission Link Load

Figure 11

issues, such as the creation of transmission congestion contracts, and focus solely on the

25

short-run dispatch and pricing issues. A market with a single transmission lines, asshown in the accompanying Figure 11, allows an illustration of the basic principles.What is less obvious, however, is that these same principles in no way depend on thespecial case of a single transmission line. Unlike many other approaches, such asownership and physical control of the line, or the contract-path fiction, as expanded belowin further examples for a grid, these pricing principles extend to a framework to supportopen access in a complicated network.

The assumptions include:

• Two locations, A and B.

• Total load is for 600 MW at location B. For simplicity, the load is fixed, withno demand bidding.

• A transmission line between A and B with capacity that will be varied toconstruct alternative cases.

• Pool bid generation at both A and B. To simplify, each location has the samebid curve, starting at 2 cents/kwh and increasing by 1 cent/kwh for each 100MW. Hence, a market price of 5 cents at A would yield 300 MW of pool-based generation at that location. Likewise for location B.

• Two bilateral transaction schedules, Blue and Red, each for 100 MW from Ato B. Each bilateral transaction includes a separate contract price between thegenerator and the customer; the SO does not know this contract price.

Blue provides a (completely discretionary) decremental bid at A of 3.5cents. In other words, if the price at A falls to 3.5 cents, Blue prefersto reduce generation and, in effect, purchase power from the pool.Blue may do this, for example, if the running cost of its plant is 3.5cents, and it would be cheaper to buy than to generate.

Red provides no such decremental bid, and requests to be treated as amust run plant.

The SO accepts the bids of those participating in the spot market at A and B andthe bilateral schedules. The load is fixed at 600 MW. The bilateral transactions cover200 MW, or the person responsible for the bilateral transaction must purchase power atB to meet any deficiency. The remaining 400 MW of load must be met from the spotmarket to include production at A or B, and use of the transmission line.

In determining the economic dispatch, the system operator treats the poolgeneration bids in the usual way. The Blue bilateral transaction is treated as a fixedobligation, with the 3.5 cent decrement bid as an alternative source of balancingadjustment at A. The Red bilateral transaction is treated as a fixed obligation, with nosuch balancing adjustment.

26

Power Flows and Locational Prices

Alternative Cases

Link Capacity A to B MW 400 300 200 100

Total Load at B MW 600 600 600 600

Price at A cents/kwh 4 3.5 3 2

Price at B cents/kwh 4 5 6 7

Transmission Price cents/kwh 0 1.5 3 5

Pool Generation at A MW 200 150 100 0

Pool Generation at B MW 200 300 400 500

Blue Bilateral Input at A MW 100 50 0 0

Red Bilateral Input at A MW 100 100 100 100

Assuming that the net of the fixed obligations with no balancing adjustments isfeasible, which is the interesting case, we can vary the capacity on the link to see theresults of the economic dispatch and the payments by the participants. The examplescover four cases, starting at 400 MW of transmission capacity, and reducing in incrementsof 100 MW. The details are in the accompanying table.

400 MW. In the case of 400 MW of transmission capacity, the economic dispatchsolution is just balanced with no congestion. Everyone sees the same price of 4 cents.The payments for each party include:

- Pool Generation at A: Paid 4 cents for 200 MW.

- Pool Generation at B: Paid 4 cents for 200 MW.

- Pool Load at B: Pays 4 cents for 400 MW.

27

- Blue Bilateral: Pays zero cents for transmission of 100 MW.

- Red Bilateral: Pays zero cents for transmission of 100 MW.

Everybody is happy.

300 MW. In the case of 300 MW of transmission capacity, the economic dispatchsolution encounters transmission congestion, and the prices differ by location. The priceat A drops to 3.5 cents, and the price at B rises to 5 cents. The opportunity cost oftransmission is 1.5 cents. The payments for each party include:

- Pool Generation at A: Paid 3.5 cents for 150 MW.

- Pool Generation at B: Paid 5 cents for 300 MW.

- Pool Load at B: Pays 5 cents for 400 MW.

- Blue Bilateral: Pays 1.5 cents for transmission of 50 MW. Blue makes up theremaining 50 MW obligation at B at a price of 5 cents.

- Red Bilateral: Pays 1.5 cents for transmission of 100 MW.

Everybody would prefer less congestion, but everyone is paying the opportunity cost ofthe transmission congestion. Note that at these prices, Blue is indifferent to bidding inits generation at 3.5 cents in the pool at A, or continuing as a bilateral transaction.Further, note that the SO reduced both pool and Blue transactions. There is no artificialbias induced by the SO fulfilling the directives of the economic dispatch.

200 MW. In the case of 200 MW of transmission capacity, the economic dispatchsolution encounters more transmission congestion, and the prices differ more by location.The price at A drops to 3 cents, and the price at B rises to 6 cents. The opportunity cost

of transmission is 3 cents. The payments for each party include:

- Pool Generation at A: Paid 3 cents for 100 MW.

28

- Pool Generation at B: Paid 6 cents for 400 MW.

- Pool Load at B: Pays 6 cents for 400 MW.

- Blue Bilateral: Prefers not to generate and has no transmission. Blue makesup the 100 MW obligation at B at a price of 6 cents.

- Red Bilateral: Pays 3 cents for transmission of 100 MW.

Everybody would prefer less congestion, but everyone is paying the opportunity cost ofthe transmission congestion. Note that at these prices, Blue is better off than if it hadactually generated. Of course, Blue would still be indifferent to bidding in its generationat 3.5 cents in the pool at A, or continuing as a bilateral transaction. Further, note thatthe SO reduced both pool and Blue transactions. There is no artificial bias induced bythe SO fulfilling the directives of the economic dispatch.

100 MW. In the case of 100 MW of transmission capacity, the economic dispatchsolution encounters transmission congestion to the point of eliminating everything otherthan the must run plant, and the prices differ more by location. The price at A drops to2 cents, and the price at B rises to 7 cents. The opportunity cost of transmission is 5cents. The payments for each party include:

- Pool Generation at A: No generation.

- Pool Generation at B: Paid 7 cents for 500 MW.

- Pool Load at B: Pays 7 cents for 400 MW.

- Blue Bilateral: Prefers not to generate and has no transmission. Blue makesup the 100 MW obligation at B at a price of 7 cents.

- Red Bilateral: Pays 5 cents for transmission of 100 MW.

Everybody would prefer less congestion, but everyone is paying the opportunity cost ofthe transmission congestion. Note that at these prices, Blue is better off than if it had

29

actually generated. Of course, Blue would still be indifferent to bidding in its generationat 3.5 cents in the pool at A, or continuing as a bilateral transaction. Further, note thatthe SO reduced both pool and Blue transactions. There is no artificial bias induced bythe SO fulfilling the directives of the economic dispatch.

Power Flows and Locational Prices

Alternative Cases

Link Capacity A to B MW 400 300 200 100

Price at A cents/kwh 4 3.5 3 2

Price at B cents/kwh 4 5 6 7

Transmission Price cents/kwh 0 1.5 3 5

Payments to Independent System Operator

Pool Load at B (400 MW) cents (x1000) 1,600 2,000 2,400 2,800

Contract Load at B (200 MW) cents (x1000) 0 0 0 0

Generation at A cents (x1000) (800) (525) (300) 0

Generation at B cents (x1000) (800) (1,500) (2,400) (3,500)

Blue Transmission cents (x1000) 0 75 0 0

Blue Imbalance at B cents (x1000) 0 250 600 700

Red Transmission cents (x1000) 0 150 300 500

Red Imbalance at B cents (x1000) 0 0 0 0

Net to SO cents (x1000) 0 450 600 500

The net spot-market payments that are made to and from the SO are summarizedin the accompanying table. Note that the cases of transmission congestion include netpayments to the SO. These net payments are equal to the value of the constrainedtransmission capacity. These are the congestion payments which would be redistributedthrough a system of transmission congestion contracts, as illustrated below in furtherexamples.

Implications

These examples for a single, isolated line are simple, but they capture the essentialfeatures. These features generalize to a more complicated network under the economicdispatch model in the sense that participants can provide bids at their discretion. Someof the bids can be "must run." The locational prices are easily determined from theeconomic dispatch considering all the bids and schedules, not just those included in thepower exchange. And although everyone would prefer a less congested system, all users

30

would pay the short-run opportunity costs of their contribution to the congestion. Otherthings being equal, there would be no bias between spot market and bilateral transactions.

Note that if Blue and Red did not pay the opportunity cost of transmission, therewould be a substantial bias in favor of the bilateral transactions. Furthermore, thelocational prices are consistent with the efficient competitive outcome, as is bestillustrated by Blue’s willingness to adjust a bilateral transaction.

Contrary to the argument above, that the SO would have a bias in favor of spotmarket transactions, the treatment of the Red bilateral transaction might lead to anaccusation that there is a reverse bias in favor of the bilateral transaction. However, thereare two important features of the pricing and access rules that run counter to thisassertion.

First, the spot market participants could achieve the same result by bidding ingeneration at A at a zero reservation price, or lower. In fact, in performing the economicdispatch, the SO treats the Red transaction as just this type of bid. Under thesecircumstances, the price at A could drop to zero, or lower, with a corresponding increasein the opportunity cost of transmission.

Furthermore, suppose that Red’s true short-term generation cost is 3 cents, but itrefused to make a decremental bid to the SO. Then in the 100 MW case above, Redwould have acted irrationally and would be worse off than if it offered such adecremental bid. It can also be shown that the cost thus imposed on Red is at least aslarge as the total cost imposed on everyone else in the market. Thus Red would pay forits own mistakes; the effect would be a net gain for the other generators and load(although there could be winners and losers, in aggregate everyone else would win).

Failure to offer a bid-based economic dispatch will return us to the complicationsand fictions of the contract-path world of old, and the many artificial arbitrageopportunities that create profit by creating confusion. This would not be good publicpolicy.

CONTRACT NETWORK EXAMPLES

For purposes of further illustration, consider the case of a three bus network withidentical lines and identical thermal limits on each line. A three bus network is theminimum case needed to observe the network interaction effects of loop flow. Here weuse the DC-Load approximation for real power only, and ignore contingency constraints.Reactive power and contingency constraints can be included without changing any of thefundamental points examined here.12

12 W. W. Hogan, "Contract Networks for Electric Power Transmission," Journal of Regulatory Economics,Vol. 4, No. 3, September 1992, pp. 211-242.

31

An alternative base case model and an allocation of congestion contracts are shown

Allocation of Capacity Rights Binds on One Line

1 3

2

Figure 12

in Figure 12. Here we assume that the desired transmission congestion contracts are for800 MW from bus 1 to bus 3, and 200 MW from bus 2 to bus 3. Or, an equivalentdefinition is that the customer at bus 3 has the contract to purchase 800 MW at bus 1 and200 MW at bus 2. The simultaneous allocation of these contracts is feasible, but it doeshit the thermal transmission constraint of 600 MW on the line between bus 1 and bus 3.

In Figure 12 the prices calculated for this dispatch are shown relative to the priceat bus 1. In this instance there is no congestion and the prices cover only the cost ofgeneration at bus 1 and the marginal cost of losses. In this simplified case, theequilibrium required is that the marginal losses are linear in the flow on any link and arethe same along any parallel path. Hence the marginal loss of one additional megawattfrom bus 1 to bus 3 is 0.075, whether by the path 1→3 or via 1→2→3. There is noadditional congestion cost, and hence there is no payment from the pool under thecongestion rental contracts. Equivalently, the customers at bus 3 buy their 800 MW frombus 1 and 200 MW from bus 2, just as specified in the transmission congestion contracts.

Of course, a change in the economics of generation could induce transmissioncongestion with the associated differences in prices across locations. In Figure 12, it was

32

economic to generate power at bus 2 and the actual economic dispatch is the same as the

Constraints with Out-Of-Merit Costs

1 3

2

Figure 13

dispatch with simultaneous use of the allocated congestion contracts. In Figure 13, theassumed conditions change with an increase in the running cost of power at bus 2 and theneed to use expensive generation at bus 3. If the gross load at bus 3 is still 1000 MW,then part of the load must be met with local generation, which costs 1.3, including acongestion rental of 0.225. At this price for bus 3 and with these loads and flows, theprice at bus 2 is determined by the equilibrium conditions of optimal economic dispatch.The easiest way to verify the equilibrium prices is to assume that an additional 2 MW ofpower could be supplied at bus 2. This would allow a reduction of 1 MW at bus 1 andan increase of 1 MW delivered to bus 3 that could displace the expensive generation atbus 3. The flow from 1→2 would reduce by 1 MW, with a corresponding 1 MW increasealong 2→3. The flow along 1→3 would still be at the limit of 600 MW, and total losseswould be the same. Hence the net savings would be 1 unit at bus 1 and 1.3 units at bus3, for a total of 2.3 units. This implies a price for the incremental generation of 2 MWat bus 2 of 2.3÷2 = 1.15, which is the equilibrium price. Along with the marginal losses,this total opportunity-cost price implies a bus 2 congestion price of 0.1125.

By assumption, the cost of the generating plant at bus 2 is above 1.15, so the plantdoes not run. Now all the power transmitted is generated at bus 1, and only 900 MW canbe transmitted. The thermal constraint of 600 MW on the line between bus 1 and bus 3

33

is binding. All the users of the grid pay or are paid these prices for the actual dispatch.In addition, the holders of the point-to-point transmission congestion contracts receivepayments from the pool operators.

The resulting payments are shown in Table IV. Hence the owner of the 800 MWcontract from bus 1 is paid the congestion rental difference from bus 1 to bus 3 of 0.225for the full 800 MW, requiring a payment from the pool of 180. Likewise, the owner ofthe 200 MW contract is paid the difference in the congestion rental between bus 3 andbus 2, or 0.1125, for the full 200 MW contract and a payment of 22.5. Both usersactually buy power from the pool at bus 3 for the price of 1.3. For the customer with the800 MW contract to purchase at bus 1, the payment of 180 is the total value of thecongestion price differential between bus 1 and bus 3. And for the customer with thecontract for 200 MW at bus 2, the payment of 22.5 is the total value of the congestionprice differential between bus 1 and bus 2.

By purchasing 200 MW at bus 3 at a price of 1.3 and then applying thetransmission congestion payment of 22.5, the holder of the 200 MW transmission contractcan in effect purchase 200 MW at the price at bus 2 and pay only the marginal losses tomove the power to bus 3. Although the actual dispatch is different than the simultaneousallocation of congestion contracts, the payments to the congestion contract holders providethe guarantee in effect that the congestion contract holders can purchase power at theprice of power at another location. This holds true even if no power was actuallygenerated at that location, as here for bus 2. Furthermore, specific performance toactually generate and transmit the 800 MW and 200 MW according to the congestioncontracts would not be feasible under this economic dispatch. Only by foregoing theadvantages of the economic dispatch, and increasing total costs, could the specific plantsbe used for specific customers. The transmission congestion contracts guarantee theeconomic value of the transmission, but do not determine the actual flows.

Table IV: Congestion with Out-Of-Merit Costs

CongestionContracts

Q (MW) CongestionPriceDifference

DirectReceipts

ExcessShare

ExcessRentals

NetReceipts

1->3 800 0.225 180 80.00% 0 180

2->3 200 0.1125 22.5 20.00% 0 22.5

Total 202.5 0 202.5

The example in Figure 13 finds the pool dispatcher collecting congestion rentalsfrom the actual users and paying the same rentals to the owners of transmissioncongestion contracts. Because the same transmission constraint limits both the actualdispatch and the initial allocation of transmission congestion contracts, there are no excess

34

congestion rentals. All the congestion revenue collected is required to compensate theholders of the point-to-point transmission congestion contracts.

An alternative case is shown in Figure 14. In this case the economics of load and

Constraint with a Shift in Loads

1 3

2

Figure 14

dispatch have changed significantly. Power still costs 1.3 at bus 3, but now the net loadis reduced to 400 MW. There is a big net load at bus 2, and the equilibrium power costthere is at 1.55. The relatively cheap generation at bus 1 is used at the level of 1100MW, which causes a shift in the flows. Now the dispatcher has no problem with athermal limit on the line between bus 1 and bus 3, but the line between bus 1 and bus 2has reached a similar thermal limit at 600 MW. This transmission constraint induces theindicated bus prices and congestion rentals.

To verify the equilibrium price at bus 2, given the prices at buses 1 and 3, notethat 1 MW of additional load at bus 2 would be met by an increment of 2 MW ingeneration (or an equivalent reduction in load) at bus 3 and a reduction of 1 MW ofgeneration at bus 1. The net change in generation cost would be 2*1.3 -1 = 1.6 units.The flow on line 1→2 would be unchanged, but the flow on line 1→3 would be reducedby 1 MW and the reverse flow along 2→3 would increase by 1 MW. Since these lineshave different marginal losses, there would be a net reduction in losses of 0.05. Hence,

35

the total increase in cost for an additional MW at bus 2 would be 1.6 - 0.05 = 1.55, theprice at bus 2.

Again the pool pays or is paid the short-run prices for power at each of thelocations. And again the pool makes payments to the holders of the point-to-pointtransmission congestion contracts. The summary of the various payments appears inTable V. For the customer with the contract for 800 MW between bus 1 and bus 3, thecongestion differential is 0.2375 and the total payment from the pool is 190. This allowsthe contract holder to purchase 800 MW at bus 3--with some of that power necessarilygenerated by plants located at bus 3--pay the price of 1.3, and after netting out thepayment of 190 from the pool, effectively purchase the 800 MW at bus 1 and pay onlymarginal losses to move the power to bus 3.

Similarly, the customer with the contract for 200 MW from bus 2 to bus 3 canpurchase 200 MW at bus 3 at the price of 1.3. However, this price is lower than theprice at bus 2, and the difference in congestion rentals is now negative, at -0.2375. Underthe terms of the point-to point contract, this customer must make an added payment of47.5 to the pool. When coupled with the purchase of 200 MW at bus 3, this is equivalentto purchasing 200 MW at bus 2 at 1.55 and then moving to bus 3 paying only themarginal losses (in this case the marginal losses also would be negative between bus 2and bus 3). The final effect is as promised under the transmission contract of thecustomer at bus 3 to purchase 200 MW at bus 2.

Table V: Constraint with a Shift in Loads

CongestionContracts

Q (MW) CongestionPriceDifference

DirectReceipts

ExcessShare

ExcessRentals

NetReceipts

1->3 800 0.2375 190 80.00% 228 418

2->3 200 -0.2375 -47.5 20.00% 57 9.5

Total 142.5 285 427.5

In this case of a shift in loads, with a new transmission constraint binding, the poolcan make all the necessary payments to the holders of the point-to-point transmissioncongestion contracts, but the payments out amount to only 190 - 47.5 = 142.5. However,the total for the congestion rentals paid by the users of the grid is700*0.475 + 400*0.2375 = 427.5. There remain excess congestion rentals of 285.Assuming that the fixed charge payments are proportional to the transmission congestioncontracts, one way to dispose of these excess congestion rentals would be to pay them outto the transmission congestion contract holders in the ratio of 80 to 20. Hence thetransmission contract holder from bus 1 would receive an additional payment of 228, fortotal receipts of 418. Likewise, the transmission contract holder from bus 2 would

36

receive 57 from the excess congestion rentals for total receipts of 9.5.

In Figure 14 there is a shift in load and economics, and one of the transmission

Constraint with a Reversal of Flows

1 3

2

Figure 15

contract holders, for power from bus 2, is required to make addition congestion paymentsto the pool. With enough of a change in the loads and transmission flows, it is possiblethat everyone with a transmission contract holds them in the reverse direction, and in thiscase the payments under the sharing of excess congestion rentals take on addedimportance. For example, consider the conditions depicted in Figure 15. Here theeconomics of the dispatch and load have changed even more dramatically compared tothe initial allocation of transmission congestion contracts. Now there is low price at bus3 and a net input of 800 MW, and the higher price is at bus 2 with a net load of 1000MW. The flows on the links from bus 3 are now reversed.

The prices at the buses include a positive congestion component at bus 2 and anegative congestion impact at bus 3, all relative to bus 1. As before, to verify theequilibrium price at bus 3, given the prices at buses 1 and 2, note that 1 MW ofadditional load (or an equivalent reduction in generation) at bus 3 would be met by anincrement of 2 MW in generation at bus 1 and a reduction of 1 MW of generation at bus2. The net change in generation cost would be 2*1 - 1.3 = 0.7 units. The flow on line2→3 would be unchanged, but the reverse flow on line 1→3 would be reduced by 1 MW

37

and the flow along 1→2 would increase by 1 MW. Since these lines have differentmarginal losses, there would be a net increase in losses of 0.025. Hence, the totalincrease in cost for an additional MW at bus 2 would be 0.7 + 0.025 = 0.725, the priceat bus 3.

Once again, the users of the grid pay or are paid according to these short-runmarginal cost prices. The pool collects the payments and, in turn, makes the necessarypayments to the holders of the transmission congestion contracts. In this case, both thecustomers with congestion contracts to bus 1 and those with contracts to bus 2 facenegative congestion rent differentials. Hence the customer with congestion contracts of800 MW from bus 1 sees a differential of -0.25, and makes a total additional payment tothe pool of 200. With the purchase of 800 MW at bus 3 at the price of 0.725, thesecombined payments are equivalent to a purchase of 800 MW at bus 1 and then movingto bus 3 at the cost of marginal losses.

For the customer with a 200 MW contract to bus 2, the congestion price differenceis -0.5, and the direct payment to the pool is 100. These payments from the contractholders to the pool add to the total congestion rentals collected by the pool from theactual users of the grid, who pay -800*(-0.25) + 1000*0.25 = 450. In all, as summarizedin Table VI, there are 750 units of excess congestion rentals. As before, these congestionrentals could be distributed according to the share in the fixed cost allocation. In thepresent example, this would provide a payment of 600 to the customer with transmissioncongestion contracts of 800 MW from bus 1, for net receipts of 400; and 150 for thecustomer with contracts of 200 MW at bus 2, for net receipts of 50.

Table VI: Constraint with a Reversal in Loads

CongestionContracts

Q (MW) CongestionPriceDifference

DirectReceipts

ExcessShare

ExcessRentals

NetReceipts

1->3 800 -0.25 -200 80.00% 600 400

2->3 200 -0.5 -100 20.00% 150 50

Total -300 750 450

In all cases, the net effect of economic dispatch, marginal cost pricing, andassignment of transmission congestion contracts is to collect congestion costs from theactual users of the grid and pay the congestion costs to those who bear the burden of thefixed charges. The transmission congestion contracts based on price differencescompromise two forms. First, point-to-point transmission congestion contracts can beoffered which provide the economic equivalent of a customer at one location alwayshaving the effective contract to buy delivered power at the cost at a distant location plusthe marginal losses. Second, to the extent that there are excess congestion rentals, these

38

rentals can be distributed according to some agreed formula. In aggregate, the congestionrentals paid are always adequate to honor the point-to-point transmission congestioncontracts, and sometimes there can be additional rents that could be dispersed accordingto a sharing formula. In some instances, the congestion payments under the point-to-pointcontracts can be negative, but only when the economics of the dispatch have switched toprovide the contract holder, who has access to cheap generation, the money from anoperating margin through the pool dispatch that can fund the congestion payments. Thetransmission congestion contract is analogous to a futures contract which provides aperfect hedge for the cash market in transmission. The pool dispatcher and operator ofthe settlements system is taking no financial risk in providing these price guarantees, andthe actual dispatch is not constrained by the transmission congestion contracts. Thedispatcher always has the freedom to provide the most economical generation possiblegiven the current costs, bids, and system constraints.

39

Economic Dispatch on a Grid

The three bus and three line example is the minimum network needed to illustratethe effects of loop flow and the impact of locational prices in a network. The results forthe three link loop can be quite different than those found for a single transmission lineor a radial connection. Analogies built on the case of a single line can be misleading.However, the analysis of the three bus case extends to more complicated networks, withone additional and important amendment. In the three bus case, it may be easy to fallinto the trap of assuming that transmission congestion contracts are connected withindividual lines between buses, since there is no difference in the geography of point-to-point definitions when every bus is connected to every other by a direct line. In a morecomplicated network, the transmission congestion contracts can be defined quiteseparately from the map of the individual lines.

Consider the simple market model in Figure 16, which will serve as the starting

7

3

MW

4

MW MW

Demand2-2:30 a.m.

At Low Demand, Gas Plants Are Idleand Market Price is 3 cents per kwh.

/kwh/kwh/kwh

Figure 16

point for a set of a succeeding examples for a grid that move to a grid with multipleloops. In this market there is one load center, a city in the east, supplied by generatorslocated far away in the west, connected by transmission lines, and by local generatorswho are in the same region as the city customers. The plants in the west consist of an

40

"Old Nuke" which can produce energy for a marginal cost of 2 ¢/kWh and a "New Gas"plant that has an operating cost of 4 ¢/kWh. These two plants each have a capacity of100 MW, and are connected to the transmission grid which can take their power to themarket in the east.

The competing suppliers in the east are a "New Coal" plant with operating costsof 3 ¢/kWh and an "Old Gas" plant that is expensive to use with a marginal cost of7 ¢/kWh. Again these eastern plants are assumed to have a capacity of 100 MW. Thetwo plants in the west define the "Western Supply" curve, and the two plants in the eastdefine the corresponding "Eastern Supply" curve. These supply curves could representeither engineering estimates of the operating costs or bids from the many owners of theplants who offer to generate power in the competitive market. For simplicity, we ignoretransmission losses and assume that the same supply curves apply at all hours of the day.

Under low demand conditions, as shown in Figure 16 for the early hours of themorning, the supply curves from the two regions define an aggregate market supply curvethat the pool-based dispatchers can balance with the customer demands. The aggregatemarket supply curve stacks up the various generating plants from cheapest to mostexpensive. The pool-based dispatchers choose the optimal combination of plants to runto meet the demand at this hour. In Figure 16, the result is to provide 150 MW. Theinexpensive Old Nuke plant generates its full 100 MW of capacity, and the New Coalplant provides another 50 MW. The New Coal plant is the marginal plant in this case,and sets the market price at 3 ¢/kWh for this hour. Hence the customers in the city pay3 ¢/kWh for all 150 MW. The New Coal plant receives 3 ¢/kWh for its output, and thisprice just covers its running cost. The Old Nuke also receives 3 ¢/kWh for all its 100MW of output. After deducting the 2 ¢/kWh running cost, this leaves a 1 ¢/kWhcontribution towards capital costs and profits for Old Nuke owners.

In this low demand case, and ignoring losses, there is no additional opportunitycost for transmission. The 100 MW flows over the parallel paths of the transmission grid.But there is no constraint on transmission and, therefore, no opportunity cost. Hence theprice of power is the same in the east and in the west. In the short run, there is nocharge for use of the transmission system.

If demand increases, say at the start of the business day, the system operator mustmove higher up on the dispatch curve. For example, consider the conditions defined inFigure 17. This hour presents the same supply conditions, but a higher demand. Nowthe pool-based dispatchers must look to more expensive generation to meet the load. TheOld Nuke continues to run at capacity, the New Coal plant moves up to its full capacity,and the New Gas plant in the west also comes on at full capacity. The New Gas plantin the west is the most expensive plant running, with a marginal cost of 4 ¢/kWh.However, this operating cost cannot define the market price because at this price demandwould exceed the available supply, and the system operator must protect the system bymaintaining a balance of supply and demand.

41

In this case, the result is to turn to those customers who have set a limit on how

7

3

MW

4

MW MW

Demand9-9:30 a.m.

At Morning Demand, New Gas Plant is Dispatchedand Market Price is 6 cents per kwh.

/kwh/kwh/kwh

Figure 17

much they are willing to pay for electric energy at that hour. This short-run demandbidding defines the demand curve which allows the system operator to raise the price andreduce consumption until supply and demand are in balance. In Figure 17 this newbalance occurs at the point where the market price of electricity is set at 6 ¢/kWh. Onceagain, the customers who actually use the electricity pay this 6 ¢/kWh for the full 300MW of load at that hour. All the generators who sell power receive the same 6 ¢/kWh,which leads to operating margins of 2 ¢/kWh for New Gas, 3 ¢/kWh for New Coal, and4 ¢/kWh for Old Nuke.

Once again, the pool-based dispatch in Figure 17 depends on excess capacity in thetransmission system. The plants in the western region are running at full capacity, andthe full 200 MW of power moves along the parallel paths over the grid to join with NewCoal to meet the demand in the east. There is a single market price of 6 ¢/kWh, andthere is no charge for transmission other than for losses, which are ignored here forconvenience in the example.

42

Transmission Constraints

With the plants running at full capacity, there might be a transmission constraint.To illustrate the impact of a possible transmission limit, suppose for sake of discussionthat there is an "interface" constraint between west and east. According to this constraint,no more than 150 MW of power can flow over the interface.

As shown in Figure 18, this transmission constraint has a significant impact on

INT

ER

FA

CE

7

3

MW

4

MW MW

Demand9-9:30 a.m.

Morning Demand & Transmission Interface Constraint Yield Congestion;Market Price is 7 cents in the East and 4 cents in the West.

Transmission Constraint Creates 3 cent Congestion Rental.

/kwh/kwh/kwh

CongestionTransmission

Figure 18

both the dispatch and market prices based on short-run marginal costs. In Figure 18 thelevel of demand from the city in the east is assumed to be the same as in the case ofFigure 17. However, now the pool-based dispatcher faces a different aggregate marketsupply curve. In effect, only half of the New Gas output can be moved to the east. Tomeet the demand, it will be necessary to simultaneously turn off part of the New Gasoutput and substitute the more expensive Old Gas generation which is available in theEast. This new dispatch increases the market price in the east to 7 ¢/kWh and necessarilyinduces a further reduction in demand, say to a total of 290 MW. The New Coal and OldGas plants receive this full price of 7 ¢/kWh for their 140 MW, which provides a4 ¢/kWh operating margin or short-run profit for New Coal and allows Old Gas to coverits operating costs.

43

In the western region, however, a different situation prevails. The transmissioninterface constraint has idled part of the output of the New Gas plant. Clearly the marketprice in the west can be no more than the operating cost of the plant. Likewise, since theplant is running at partial output, the market price can be no less than the operating costof 4 ¢/kWh. This is the price paid to New Gas and Old Nuke, which covers New Gasoperating costs and provides Old Nuke an operating margin of 2 ¢/kWh.

The 3 ¢/kWh difference between the market price in the east and the market pricein the west is the opportunity cost of the transmission congestion. In effect, ignoringlosses, the marginal cost of transmission between west and east is 3 ¢/kWh, and this isthe price paid implicitly through the transactions with the system operator. Electricityworth 4 ¢/kWh in the western region becomes worth 7 ¢/kWh when it reaches the easternregion.

The transmission "interface" constraint is a convenient shorthand for a more

7

3

MW

4

MW MW

Demand9-9:30 a.m.

Transmission Constraint May Be A Contingency Limit,Here Protecting Against Loss of Northern Line.

Contingency Constraint Still Creates 3 cent Congestion Rental.

/kwh/kwh/kwh

CongestionTransmission

Figure 19

complicated situation handled by the pool-based dispatchers. The interface limit dependson a number of conditions, and can change with changing loads. Typically it is not thecase that there is a 75 MW limit on one or both of the parallel lines through which poweris flowing in the grid. In normal operation, it may well be that the transmission lines

44

could individually handle much more flow, say 150 MW each or twice the actual use.At most normal times, the lines may be far from any physical limit. However, the pool-based dispatchers must protect against contingencies--rare events that may disruptoperation of the grid. In the event of these contingencies, there will not be time enoughto start up new generators or completely reconfigure the dispatch of the system. Thepower flow through the grid will reconfigure immediately according to the underlyingphysical laws. Hence, generation and load in normal times must be configured, andpriced, so that in the event of the contingency the system will remain secure.

For instance, suppose that the thermal capacity of the transmission lines is 150MW, but the pool-based dispatchers must protect against the loss of a northerntransmission line. In this circumstance, the actual power flows may follow Figure 18,with 75 MW on each line, but the pool-based dispatchers must dispatch in anticipationof the conditions in Figure 19. Here the northern line is out, and in this event the flowon the southern line would hit the assumed 150 MW thermal limit. This contingencyevent may never occur, but in anticipation of the event, and to protect the system, thesystem operator must dispatch according to Figure 19 even though the flows are as inFigure 18. In either case, the transmission constraint restricts the dispatch and changesthe market prices. The price is 4 ¢/kWh in the west and 7 ¢/kWh in the east, with the3 ¢/kWh differential being the congestion-induced opportunity cost of transmission. This"congestion rental" defines the competitive market price of transmission.

Buying and selling power at the competitive market prices, or charging fortransmission at the equivalent price differential provides incentives for using the gridefficiently. If some user wanted to move power from east to west, the transmission pricewould be negative, and such "transmission" would in effect relieve the constraint. Thetransmission price is "distance- and location-sensitive," with distance measured inelectrical rather than geographical units. And the competitive market prices arisenaturally as a by-product of the optimal dispatch managed by the system operator.

The simplified networks in Figure 16 through Figure 19 illustrate the economicsof least-cost dispatch and locational prices. However, these networks by design avoid thecomplications of loop flow that can be so important in determining prices and creatingthe difficulties with physical transmission rights. The extension of these examples andthe basic pricing properties to more complicated networks includes the possibility ofinputs and load around loops in the system. Here assume a transmission system as beforebut with the basic available generations and loads as shown in Figure 20. Thesegenerators define a basic supply configuration with quantities and prices, coupled with theassociated loads, and all with the following characteristics:

• Generation available at four locations in the East (Y, Z) and West (A, B).

• Load in the East, consisting of the Yellow LDC at V and the Orange, Red andBlue LDCs at W.

45

• Load in the West, consisting of a Green LDC at C.

System Configuration

Orange LDC Blue LDCRed LDC

New Gas #1

75 MW 40 MW 35 MW

A

B

C

D

M

N

W

X

Y

Z

100 MW

New Gas #2

100 MW

Old Nuke

100 MW2

Old Gas #1

50 MW

Old Gas #2

50 MW

New Coal

100 MW

3

Green LDC

20 MW4

3.5 5

7

V

Yellow LDC

15 MW

150 MW

INT

ER

FA

CE

90 MW

90 MW

Figure 20

• Interface constraint of 150 MW between bus D and buses M and N.

• Thermal constraints of 90 MW between M and X and between N and X.

• The New Gas and Old Gas generating facilities each consist of two generatingunits whose marginal costs of production differ.

Loads in Figure 20 are illustrative and will vary systematically in each example.For convenience, losses are ignored in all examples.

The first example to introduce the effect of loop flow involves a new sources ofsupply at a location on the loop. Here a low cost, large capacity generator becomesavailable in Figure 21 at bus "P." An IPP at bus "L" has bid in a must run plant at 25MW, having arranged a corresponding sale to the Yellow distribution company at bus

46

"V". Were it not for the IPP sale, more power could be taken from the inexpensive

New Gen.

25 MW

P

Orange LDC Red LDC Blue LDCGreen LDC

New Gas Old Gas

70 MW

Old Nuke

A

B

C

D

M

N

W

X

Y

Z

Bilateral Transaction Between IPP and Yellow LDC Increases Congestion

New Coal

100 MW

25 MW

65 MW

65 MW 90 MW

90 MW

100 MW

320 MW

25 MW 200 MW 50 MW

55 MW

65 MW

New IPP

L

Yellow LDC

V25 MW

25 MW

25 MW

3.5

3.75

3.25

7

3

7

5

3.25

4

3.5

2

150 MW

INT

ER

FA

CE

90 MW

90 MW

25 MW

Figure 21

generators at bus "P" and at bus "A". However, because of the effects of loop flow, theseplants are constrained in output, and there are different prices applicable at buses "D","M", "N", and "X".

In a further example the constraints are modified to replace the interface limit withlimits on the flows on individual lines. Here every line in the main loop is constrainedby a thermal limit of 90 MW, replacing the interface limit. With these constraints inFigure 22, an added load of 150 MW at bus "L" alters the flows for the marketequilibrium. In this case, the combined effect of the increased load and the constraintsleads to a price of 8.25¢ per kWh at bus "L". This illustrates that it is possible to havemarket clearing prices at some locations that are higher than the 7¢ marginal running costof the old gas plant at bus "Y", the most expensive plant in the system. The interactionof the network constraints is such that with a reduction of load at bus "L" it would bepossible to reduce out put of the most expensive plant by even more, and make up thedifference with cheaper sources of supply, causing the high price for load at bus "L".

Changing the network further adds new loops and even more examples of the effecton prices and dispatch caused by the network interactions. In this case, a new line hasbeen added to the network in Figure 23, connecting bus "N" to bus "M". This line is

47

assumed to have a thermal limit of 50 MW. The new line adds to the capability of the

New Gen.

125 MW

P

Orange LDC Red LDC Blue LDCGreen LDC

New Gas Old Gas

70 MW

Old Nuke

A

B

C

D

M

N

W

X

Y

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Congestion and Loop Flow Create High and Low Prices

New Coal

80 MW

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Figure 22

network in that the new pattern of generation lowers the overall cost of satisfying thesame load. The total cost reduces from $20,962.50 in Figure 22 to $19,912.50 inFigure 23. Although the average cost of power generation fell, the marginal cost ofpower increased at bus "L", where the price is now 10.75¢ per kWh. The new loopprovides more options, but it also interacts with other constraints in the system. This setof interactions is the cause of the high price as it appears at bus "L".

As a final example that confirms the sometimes counterintuitive nature of least-costdispatch and market equilibrium prices, add a new bus "O" between bus "M" and bus "N"in Figure 24, and lower the limit to 30 MW between bus "O" and bus "M". Bus "O" hasa small load of 15 MW. The increased load of 15 MW at bus "O" actually lowers thetotal cost of the dispatch, as reflected in the negative price. Each additional MW of loadat bus "O" changes the flows to allow a dispatch that lowers the overall cost of meetingthe total load. The optimal solution would be to pay customers at "O" to accept dumppower, thereby relieving congestion elsewhere and providing benefits to the overallsystem.

This final example, therefore, illustrates and summarizes the types of interactions

48

that can develop in a network with loop flow. Power can flow from high price nodes to

New Gen.

75 MW

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Orange LDC Red LDC Blue LDCGreen LDC

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Figure 23

low price nodes. The competitive market clearing price, equivalent to the marginal costsfor the least-cost dispatch, can include simultaneously at different locations prices higherthan the cost of the most expensive generation and lower than the cost of the cheapestgeneration source.

Zonal Versus Nodal Pricing Approaches

Application of the principle of locational pricing implies that transmissioncongestion would lead to many prices. Even with only a single constraint, there couldbe a different price at each location. The use of locational prices has been described asbeing too complex, with the implication that an alternative approach would produce asimpler system. A common response to this assertion has been to recommend a "zonal"approach that would aggregate many locations into a smaller number of zones. Theassumption has been that this would tend to reduce complexity. However, in the presenceof real constraints in the actual network, the zonal approach may not be as simple as it

49

might appear without closer examination.13

New Gen.

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A Tight Constraint from Bus O to Bus M Yields a Negative Price

New Coal

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OTan LDC15 MW -0.75

50 MW

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W

Figure 24

The difficulties would arise in the context of a competitive market whereparticipants have choices. If the actual operation of the network system does not conformto the pricing and zonal assumptions, there will be incentives created to deviate from theefficient, competitive solution. In the presence of a vertical monopoly that can ignore theformal pricing incentives, this has not been a problem. But under the conditions of amarket, where participants will respond to incentives, the complications created by a zonalapproach may be greater than any complications that would exist with a straight locationalapproach to pricing and transmission charging.

Consider the simplified example in Figure 25. The network has been constructedso that there are only radial connections. With strictly radial connections, locations withinand between unconstrained zones would have a common price. Hence, aggregation oflocations offers an apparent simplification by reducing to a few distinct zones. Thismotivation from a typical radial examples leads to the assumption that in general therecould be areas in a real network that would have the same prices and, therefore, these

13 For a similar analysis with similar conclusions, see Steven Stoft, "Analysis of the California WEPEXApplications to FERC," Program on Workable Energy Regulation, University of California, October 8, 1996.

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locations could be aggregated into zones that would be simpler for participants in market

New Gen.

142.5 MW

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New Coal

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Zone I Zone II Zone III

142.5 MW

Figure 25

operations.

There are two problems with this line of argument. First, if the multiple locationstruly do have the same prices, then there is no need to aggregate into zones. The pointof the aggregation was to reduce the number of prices, and in the case where theassumption of common prices holds, aggregation would be unnecessary.

Second, the definition of a zone, which appears easy in the case of a radialnetwork, becomes more problematic in the case of a more realistic network with loopflows. The radial examples can be a poor guide to thinking about interactions innetworks. For example, it is often argued, or assumed, that congestion or differences inprices between zones would be caused only by transmission constraints that could bedefined for lines that connect the zones. Furthermore, it is often assumed that differencesin prices within zones can only be caused by congestion on lines within the zone. Underthese simplifying assumptions, therefore, it is assumed that zones can be well defined andthat what happens within a zone can be treated independently of what happens betweenzones, or independently of what happens in other zones. When we move beyond theradial examples, however, these assumptions and the associated conclusions can be false.

51

With the more typical case of loops in a network, prices could differ within and

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Zone I Zone II Zone III

Figure 26

between "unconstrained" zones due to the indirect effects of "distant" constraints.Consider the slightly modified example in Figure 26. In this case, the zones developedfrom the radial analogy produce a very different outcome from the assumptions derivedfrom the radial case in Figure 25. In this example, the prices within "Zone II" differ, butthere is no binding constraint in the zone. The lines within the zone are operating belowtheir thermal limits. The difference in prices between buses M and N arises not due toconstraints within the zone but because of the loop flow effects interacting with thebinding constraints between the zones. Apparently the determination of prices within azone can not be made independent of the effects on constraints outside the zone.

A symmetric result appears in Figure 27 with a different pattern of loads and flows.In this case, there is no constraint binding between Zones II and III, but the price in ZoneIII differs from the prices in Zone II. Again this effect cannot be seen in radial networks,but it is easy to create in real networks with loop flow. The price in Zone III differs fromall the other prices in part because of the interaction with the constraints in Zone II. Ina sufficiently interconnected network, these examples suggest that a wide variety ofpricing patterns would be possible. In fact, with loop flow, it is possible for a singlebinding constraint to result in different prices at every location in the system, reflecting

52

the fact that every location has a different impact on the constraint.

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Figure 27

Aggregation into zones may add to complexity and distort price incentives. Theassertion that conversion to zones will simplify the pricing problem is not supported byanalysis of the conditions that can exist in a looped network. Furthermore, aggregatingnetworks presents a number of related technical problems that follow from the fact thatexact aggregation requires first knowing the disaggregated flows. In other words, the firststep in calculating consistent aggregate flows and prices is to calculate the disaggregatedflows and prices. Hence aggregation produces no savings in computation, and noadditional simplicity. If no price dispersion exists, no aggregation is necessary. And ifprice dispersion does exist, aggregation only sends confused price signals. In the end, thesimplest solution may be to calculate and use the locational prices at the nodes, withoutfurther aggregation.

Transmission Congestion Contracts

The congestion rental received by the system operator provides the key to definingproperty rights in the transmission grid. In the face of transmission constraints, priceswill be more volatile and it will not be possible for a generator to provide guaranteed

53

price stability in the form of a long-term contract with a customer. Furthermore,customers and generators will have an incentive to expand the grid only if they recognizeand believe that after making an investment in the grid there will be some protectionagainst any future congestions costs. A simple way to define the property right andprovide this guarantee is to assign the congestion rental not to the system operator but tothe holder of the transmission congestion contract. In the transmission constrained casesof Figure 18 or Figure 19, the congestion contracts for a total 150 MW of power mighthave been held by customers in the city, or by generators in the west. In either case, thisright is defined only as the right to collect the congestion rental. The generators andcustomers would not control the use of the grid. The system operator would determinethe efficient pattern of use through economic dispatch. The system operator would collectthe congestion payments from the actual users of the grid and pay them in turn to theholders of the transmission congestion contracts.

With this definition of transmission congestion contracts, it is an easy matter forgenerators at Old Nuke and New Gas to arrange long-term contracts that provide pricestability for customers in the city. For example, the owners of Old Nuke may haveacquired power contracts for 100 MW, and signed long-term contracts that guaranteed toprovide power delivered to the city at a price of 5 ¢/kWh. In the case of low demand asin Figure 16, the short-run price is only 3 ¢/kWh, which customers pay and generatorsreceive through the system operator. Separate from the system operator, the customerspay Old Nuke the difference of 2 ¢/kWh owed under the contracts. If demand shifts tothe higher case in Figure 17, the market price is 6 ¢/kWh, and again the customers payand generators receive this short-run price through the system operator. In this event, thegenerators separately pay the customers the difference of 1 ¢/kWh required under thelong-term contract.

When transmission constraints bind as in Figure 18 or Figure 19, the price paid bythe customers to the system operator is 7 ¢/kWh, and the price received by the generatorsfrom the system operator is 4 ¢/kWh. If the generators own the transmission congestioncontracts, then the system operator pays the generators an additional 3 ¢/kWh whichallows the generators in turn to pay the customers the 2 ¢/kWh difference agreed to bycontract. The owners of Old Nuke are always making an operating margin of 3 ¢/kWh,and the customers are always receiving the equivalent of 5 ¢/kWh electricity. Likewise,if the customers own the transmission congestion contracts, the customers receive the3 ¢/kWh from the system operator and in turn pay 1 ¢/kWh to the generators. Again theowners of Old Nuke are always making an operating margin of 3 ¢/kWh, and thecustomers are always receiving the equivalent of 5 ¢/kWh electricity. Furthermore, ineither case the system operator ends up with no transmission congestion rentals; thesystem operator serves only to pass through the congestion costs from the actual users ofthe grid to the holders of the property rights in the economic interest of the transmissiongrid.

This system of transmission congestion contracts and payments back and forth mayseem unnecessary and cumbersome in the case of the simple system of Figure 16 throughFigure 19. After all, couldn’t the pool-based dispatchers in effect assign the generation

54

from Old Nuke to the long-term customers in the city? In principle, this specificperformance model--assigning particular generation to particular users--is possible in thissimple case, but it does not generalize into the more complicated reality of aninterconnected grid with many different sites of load and generation, real and reactivepower, thermal and voltage limits, and multiple contingencies. The examples in Figure 21through Figure 24 illustrate the difficulties attendant to the network interactions. It isimpossible in a real system to meaningfully assign any particular sources and destinationof electricity, and attempts to do so can only serve to compromise the efficiency objectiveof maintaining an optimal dispatch which may require only partial use of plants inconstrained regions, violating the assumptions of specific performance. However, thepayments of congestion rentals from the system operator to the holders of point-to-pointtransmission congestion contracts do generalize to the more complicated case, and allowoptimal dispatch for efficiency while accommodating long-run contracts for pricedifferences and congestion rentals, contracts that provide both stability and the essentialprotection of investment in the network.

These point-to-point price protection transmission contracts defined in alternativeequivalent ways, with various advantages for implementation and interpretation. Forexample:

• Difference in Congestion Costs. Receive the difference in congestioncosts between two buses for a fixed quantity of power.

• Purchase at a Distant Location. Purchase a fixed quantity of powerat one location but pay the price applicable at a distant location.

• Dispatch with No Congestion Payment. Inject and remove a fixedquantity of power without any congestion payment.

The total quantity of these transmission congestion contracts can be defined for agiven configuration of the network, and the congestion contracts guaranteed for anypattern of loads in the network. In a real system, the transmission congestion contractswould respect all the constraints in the grid, including contingency constraints for thermallimits on lines and voltage limits at buses.

The point-to-point congestion contracts can be provided by the pool and allowprotection of new investment in generation and transmission. The pool takes no risk inoffering these transmission congestion contracts because the revenue collected from userspaying at short-run marginal cost is always great enough to honor the obligations underthe congestion contracts. Under certain circumstances, the revenues collected by the gridwill be greater than the obligations on the point-to-point congestion contracts, and therewill be "excess congestion rentals." For example, if there are no point-to-point contractsassigned, then none of the congestion rental would be paid out under such contracts. Inthe more interesting cases, if point-to-point congestion contracts are assigned up to thelimit of some transmission constraint, it is possible that some other network constraintwill be binding in the actual dispatch. In these cases, there will be more than enough

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revenues to honor the rental or purchase rights, and the pool will face the added task ofallocating the excess congestion rentals.

The natural assignment of any excess rentals is to those who are paying the fixedcharges. There is no single rule for allocating the rights to the excess congestion rentals.The rule examined here is to share the revenues according to the share of the fixedcharges. Hence, the owners of the grid who commit to pay the fixed charges have accessto two types of well defined and tradeable transmission congestion contracts: the point-to-point rental contract and a share in any excess congestion rentals.

As shown in Figure 28, the contract network must anchor to the same locations,

Contract Network Connects with Real Network

Real Network

Contract Network

Zonal Hub

Local Bus

Determine Locational Prices for Real Network; ImplementTransmission Congestion Contracts and Trading on Contract Network

Figure 28

but the point-to-point contracts can follow a very different geography. Market hubs canarise and be included, with the contract connections in the network following aconfiguration convenient for contracting and trading. The separation of the physical andthe financial flows allows this flexibility with the congestion revenues always sufficientto cover the obligations under transmission congestion contracts, no matter what theresulting pattern that appears in the least-cost dispatch.

To illustrate this conclusion for a more general network, consider again the

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example network in Figure 24. For this example, consider the extreme case where themarket has elected to use bus "O" as the market hub, with transmission congestioncontracts all defined relative to this hub. Generators may have the contracts to get to themarket at "O". Customers may have similar contracts to get from the market at "O" totheir own locations. The individual transmission congestion contracts may embody flowswhich would never be individually feasible, especially given the limits on the linesconnecting "O" and the unusual conditions in this extreme case. As long as the collectiveflows under the contracts would be feasible, however, the congestion costs collected willalways be sufficient to meet obligations under transmission congestion contracts, even inthis extreme case.

Here Table VII offers with two feasible sets of transmission congestion contracts(TCCs) for a hub at "O". If the only inputs and outputs in the system consisted of thosewith TCC 1 at 180 MWs in at "D", 30 MWs in at "M", 30 MWs in at "N", 60 MWs outat "O" and 180 MWs out at "X", the flows would be feasible even though the individualcontracts appear to require flows that are not feasible. Similarly for TCC 2. With thesefeasible transmission congestion contracts, alternative dispatch cases illustrate the impactof the changing congestion payments.

Table VII: Transmission Contract Allocations

From-To TCC 1 (MW) TCC 2 (MW)

"D-O" 180 160

"O-X" 180 160

"M-O" 30 10

"N-O" 30 70

The results summarized in Table VIII capture the outcomes for economic dispatchwith the only change being three different assumptions about the load at bus "L" inFigure 24, ranging from 0 MW to 150 MWs, with all other conditions the same. Thetable shows the corresponding prices at key buses, ignoring losses, and the associatedcollection of congestion rents. These rents are compared in turn with the obligationsunder the point-to-point contracts of the two sets of transmission congestion contracts.In the case of no load at "L", the congestion payments amount to $6300. Under the TCC1 the obligation is also $6300; under TCC 2 the point-to-point obligation is $5750,leaving an excess of congestion payments to be disbursed through a sharing formula.

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Table VIII: Transmission Congestion Payments

Loadat "L"

Bus Prices

¢/kWh

TotalRents $

TCC 1 TCC 2

MW "D" "M" "N" "O" "X"

0 3.50 3.75 3.25 3.50 7.00 6300 6300 5750

50 3.50 5.58 3.25 4.15 7.00 6300 6138 6084

150 3.50 10.75 3.25 -0.75 7.00 10950 1650 1650

As the load at bus "L" increases, dispatch reconfigures and prices change. Powerflows are different than in the transmission congestion contracts. However, in every caseand for each set of TCCs, the congestion rentals equal or exceed the obligations under thepoint-to-point contracts. The transmission congestion contracts can always be honored,no matter what the pattern of load. In some instances, there will be excess congestionrentals to disburse, but transmission congestion contract holders will always be able tohedge power contracts without requiring physical transmission rights and withoutcompromising the least-cost dispatch.

- end -